IR 05000331/1998014

Insp Rept 50-331/98-14 on 981014-1124.No Violations Noted. Major Areas Inspected:Operations,Engineering,Maint & Plant Support

ML20198H761
Person / Time
Site:	Duane Arnold
Issue date:	12/18/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20198H758	List: IR 05000331/1998014 ML20198H756
References
50-331-98-14, NUDOCS 9812300013
Download: ML20198H761 (15)

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a U. S. NUCLEAR REGULATORY COMMISSION REGION 111 I

Docket No: 50-331 l License No: DPR-49 Report No: 50-331/98014(DRP)

L l' Licensee:- Alliant, IES Utilities Inc.

l 200 First Street P. O. Box 351 Cedar Rapids, IA 52406-0351 l

l Facility: Duane Arnold Energy Center Location: Palo, Iowa

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Dates: October 14 through November 24,1998 inspectors: P. Prescott, Senior Resident Inspector M. Kurth, Resident inspector Approved by: R. D. Lanksbury, Chief Reactor Projects Branch 5 9612300013 981'218 PDR ADOCK 05000331 G PDR l

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l EXECUTIVE SUMMARY Duane Arnold Energy Center Duane Amold Inspection Report 50-331/98014(DRP)

This inspection included the resident inspectors' evaluations of aspects of licensee operations, engineering, maintenance, and plant suppor Operations

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The conduct of operatons continued to be professional. Operations personnel performed an error-free power reduction for the scheduled control rod sequence -

exchange and main turbine valve testing. The inspectors noted good coordination between operations and reactor engineering personnel during the evolution (Section 01.1).  !

The licensee adequately completed planned actions for cold weather preparations (Section O2.2).

Maintenance

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In general, the licensee conducted surveillance testing and maintenance activities in an acceptable manner. The inspectors observed good planning and execution of maintenance activities for the "A" residual heat removat service water system maintenance outage and low pressure coolant injection check valve modification l Installation (Section M1.1).

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The inspectors noted several examples of failures to enter equipment issues identified by the inspectors into the corrective action program by writing action requests. For J example, operators did not write action requests for a mechanical problem with a l standby diesel generator overcurrent relay flag staying in position and evidence of l

animal intrusion in an electric fire pump control panel (Section M2.1).

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The inspectors identified that a gag had been left installed, but not engaged, on a j pressure relief valve for the containment nitrogen makeup header. Maintenance  !

personnel had left the gag in place so that it would not be misplaced but failed to l adequately account for the potential of the gag inadvertently engaging (Section M2.1). I Enaineerina

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The inspectors identified that the applicable system engineer was not aware that a gag had been left installed on a pressure relief valve for the containment nitrogen makeup header (Section M2.1).

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The licensee did not adequately consider long term problems with leakage past the low pressure coolant injection (LPCI) check valve and shutdown cooling system isolation valve during development of the modification to prevent LPCI check valve chattering (Section E1.2).

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i The licensee identified three instances in which the plunger nut and auxiliary contact operator gap on 4160 volt breakers was greater than prescribed in applicable procedures but the breakers remained operable. The system engineer's root cause evaluation and corrective actions, including clarifying the maintenance procedure and personnel briefings, were thorough (Section E1.3).

Plant Sucoort

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~ The inspectors concluded that radiological practices observed during maintenance activities and daily walkdowns were adequate (Section R1.1).

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l Report Detalig Summary of Plant Status The plant began this inspection period at 100 percent power. On November 14 and 15,1998, the licensee reduced power to approximately 60 percent for several hours to perform control rod sequence exchange and main turbine valve testing. The plant was operated at approximately 100 percent power the remainder of the perio l. Operations 01 Conduct of Operations 01.1 General Comments  !

I Insoection Scope (71707)

l The inspectors followed the guidance of Inspection Procedure 71707 and conducted frequent reviews of plant operations. This included observing control room activities, reviewing system tagouts, and attending shift turnovers and crew briefings. The inspectors observed the November 14 and 15,1998, planned power reduction for the control rod sequence exchange and main turbine valve testin ;

i Observations and Findinas  :

The conduct of operations was professional. The inspectors observed strict use of procedures and thorough shift turnovers. Operations personnel performed an error-free and well-controlled power reduction for the control rod sequence exchange and main turbine valve testing. Operators and reactor engineering personnel exhibited good coordination throughout the evolutio Con @aions The conduct of operations continued to be professional. Operations personrel performed an error-free power reduction for the scheduled control rod sequence exchange and main turbine valve testing. The inspectors noted good coordination between operations and reactor engineering personnel during the evolutio Operational Status of Facilities and Equipment O2.1 General Plant Tours and System Walkdowns (71707)

The inspectors followed the guidance of Inspection Procedure 71707 in walking down accessible portions of several systems. The systtms chosen, based on maintenance work activities and probabilistic risk significance, were:

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Residual heat re" oval system (RHR)

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Containment nitrogen makeup system Equipment operability, material condition, and housekeeping were acceptable in all

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l cases. The inspectors identified two concerns as a result of these walkdowns. Relief l valves on the RHR system that were gagged with a device to prevent movement were not identified as " abandoned in placo." Also, a containment nitrogen makeup system check valve had a gag left in place. See Section M2.1 for detail .? Cold Weather Preparations Inspection Scope (71714)

The inspectors reviewed the licensee's program for protecting safety-related systems from the negative effects of ccid weather. The inspectors reviewed applicable licensee

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documentation, interviewed operations staff, and conducted plant system walkcown Observations and Findinas Operations personnel completed Integrated Plant Operating instruction (IPOI)-6, " Cold Weather Operations," Revision 13, prior to the onset of cold weather. The inspectors evaluated the well water cump houses, cooling tower valve and breaker houses, pump house, and the intake structure and found the areas adequately heated using thermostat controlled unit heaters. The inspectors observed operations personnel verifying the adequacy of area building temperatures during their performance of daily round The inspectors verified that Attachment 1, " Plant Winterization Check List," of IPOl-6 was completed, signed, and dated by the appropriate personnel. The inspectors identified no discrepancies for cold weather preparation Conclusions Prior to the onset of cold weather the licensee completed planned actions for cold weather operations. The licensee provided adequate protection to plant components and systems from cold weather effect _ _ _ _ _ - _____ - __ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

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11. Maintenance l l

M1 Conduct of Maintenance M1.1 General Comments Insoection Scope (62707 and 61726)

The inspectors dserved all or portions of surveillance test and work request activities and reviewed the applicable surveillance test or work package documentation. Specific tests and work request activities observed are listed below:

Maintenance Activities

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Preventive mainterance action request (PMAR) 1105992: lY2A regulating transformer uninterruptable 125V AC; perform calibration procedure on Elgar regulating transformer

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PMAR 1105929; IPO48 electric fire pump; inspect motor controller IC-115

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Corrective maintenance action request (CMAR) A47032: IP-022A "A" RHR service water pump motor; rewind motor, reinstall, and return leads

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PMAR 1106184: MO-1947 RHR heat exchanger IE-2018 service water outlet isolation; perform static and dynamic valve operating and testing evaluation

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CMAR A48015: "A" standby diesel generator (SBDG); replace generator bearing

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CMAR A39107: "B" core spray pump breaker IA404; breaker gap to auxiliary contacts exceeded tolerance requirements

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Engineering Change Package E-1614: low pressure coolant injection check valve modification

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CMAR A41968: "B" RHR service water pump motor; rewind motor, reinstall and return leads Surveillance Test Activities

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Surveillance Test Procedure (STP)-3.3.3.1-09: " Valve Position Indicator Verification - Operating"

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S TP-3.3.6.1-01: " Shutdown Cooling System isolation, Reactor Steam Dome Pressure - High Channel Calibration"

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STP-3.8.1-06: " Standby Diesel Generators Operability Test (Fast Start)"

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STP-45C001-Q: "RHR Service Water [SW] System Leakage Inspection Walkdown"

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STP-46G024: " Control Building / Standby Gas Treatment System Instrument Air Compressors Quarterly System Leakage and Capacity Test" Observations and Findinas The inspectors determined that in general, the work associated with these activities was conducted in a professional and thorough manner. Technicians were knowledgeable of their assigned tasks and work document requirements. The inspectors noted good planning and execution of the "A" and "B" RHRSW pump motor rewind maintenance outage and low pressure coolant injection (LPCi) check valve modification installatio The inspectors focused particular attention on these two systems because of their probabilistic risk significance. The licensee displayed proper sensitivity to the risk significance of these systems by restoring them to an operable status in a timely fashio Conclusions in general, surveillance test and maintenance activities were conducted in an acceptable manner. The inspectors observed good planning and execution of maintenance activities for the "A" RHRS'I system maintenance outage and LPCI check valve modification installatio M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Plant Material Condition Inspection Scope (62707 and 37551)

The inspectors noted several equipment issues during routine plant walkdowns. These issues were discussed with the appropriate licensee personne Observations and Findinas During this inspection period, the inspectors noted several examples of a lack of adequate documentation of identified problems. The inspectors and electrical maintenance (EM) technicians noted significant evidence of animalintrusion during performance of preventive maintenance activities conducted October 15,1998, on the electric fire pump IP-48 control panel. The inspectors discussed the problem with the system engineer. The system engineer had the EM technicians seal the one conduit line not previously sealed. As-found conditions were documented as " normal" on the

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PMAR. In the " action taken" section of the PMAR, the EM technicians documented that the conduits were sealed with duct seal to prevent mice from entering the conduits. No action request (AR) was generated. The inspectors noted in the previous PMAR similar conditions were documented. The electric fire pump control panel was located in the pump house. The inspectors performed a review on past PMARs of several other

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t control panels in the pump house to verify this was not a generic problem. No other evidence of animalintrusion had been documente On October 14,1998, the inspectors noted that single phasing relay 147\DG.31 for the

"A" SBDG had the time overcurrent relay flag in the tripped position. The inspectors notified the control room. The following day, the inspectors noted that the problem had not been logged in the control room log book. The inspectors inquired as to what had been done. The operations shift manager said the system engineer had been notified the day before, but had not yet notified operations of the resolution. The shift manager contacted the system engineer again. The system engineer later informed operations personnel that this was a problem that had occurred before and was r.ot an operability concern but a mechanical problem with the flag not staying in position. The resolution was logged in the shift supervisor's log. An auxiliary operator reset the time overcurrent relay flag. No AR or work request was writte On November 13,1998, during a plant tour, the inspectors noted that the same relay flag was again in the tripped position. The inspectors notified the operations' shift manager. The system engineer reouested that operators write a work request to repair the relay after the second occurrence. The operators reset the time overcurrent relay flag. Again, no AR was writte During a plant tour, the inspectors noted that the "A" and "B" RHR heat exchanger inlet pressure relief valves were gagged shut. A review of the maintenance database and piping and instrumentation diagrams indicated the valves were retired in place. The inspectors discussed this with the system engineer. The licensee had performed an engineering evaluation. The relief valves were for the steam condensing mode of RH The engineering evaluation documented this mode of RHR was no longer considered necessary. However, the valves were not identified with the usual " abandoned in place" tags. Licensee management informed the inspectors that the equipment abandoned in place policy was under review to improve consistenc During a plant tour on November 9,1998, the inspectors noted that pressure safety valve PSV-4344 containment nitrogen makeup header pressure relief valve had a gag

installed, but the gag adjustment screw was not all the way down. There was approximately a 1/4 inch gap. The inspectors discussed this with the system enginee The system engineer was unaware the valve had a gag installed but later discovered that maintenance personnel sometimes left gags installed so the gags would not be misplaced. The inspectors discussed with licensee management the potential for the gap between the adjustment screw and relief valve set screw to be insufficient or the adjustment screw to vibrate down and prevent the relief valve from either fully opening or not opening at all. The licensee removed the locking screw from the gag. No AR was writte Conclusions The inspectors noted several examples of failures to enter equipment issues identified by the inspectors into the corrective action program by writing ARs. For example, operators did not write ARs for a mechanical problem with a SBDG overcurrent relay flag staying in position and evidence of animalintrusion in an electric fire pump pane i

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The inspectors also noted that the applicable system engineer was unaware that a gag had been left installed on a pressure relief valve on the containment nitrogen makeup header. So the gag would not be misplaced, maintenance personnel had left the gag installed, but not engaged. The maintenance personnel had not adequately accounted for the potential of the gag inadvertently engagin '

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'E1 Conduct of Engineering E General Comments (37551)

The inspectors evaluated engineering involvement in the resolution of emergent material condition problems and other routine activities. With respect to these problems and activities, the inspectors reviewed areas such as operability evaluations, root cause analyses, safety committees, and self-assessments. Where applicable, the inspectors also examined the effectiveness of the licensee's controls for the identification, resolution, and prevention of these problem E1.2 LPCI Check Valve Modification installation Insoection Scope (37551 and 62707)

The inspectors observed the LPCI check valve modification installation,

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post-modification testing, troubleshooting, and management update meetings. The inspectors also reviewed the work order package and associated engineering change package (E-1614) modification documentatio b.- Observations and Findinas Historical Backaround On November 24,1996, the licensee identified chattering of the "A" LPCI loop check valve, V20-0082. The piping downstream of the "A" LPCI check valve injected into the

"A" recirculation pump discharge piping. The valve was required to open for LPCI and shutdown cooling modes of RHR. The licensee suspected that pressure spikes from the recirculation pump and the resulting flow turbulence were causing the LPCI check valve disc to impact the valve seat. The licensee attributed the chattering to the check valve disk moving more freely due to maintenance performed during refueling outage 1 Testing indicated that as differential pressure (dp) decreased across the valve, due to check valve leakage, the valve would begin chattering. Discussions between licensee engineering personnel and the valve vendor indicated the chattering should not prevent the valve from performing its design function. However, check valve V20-0082 would

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,'. degrade slowly over time due to service conditions. The valve had not degraded to an unacceptable level nor was it expected to degrade significantly over the current cycle per the licensee's operability determinatio ,.

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Modification Installation Engineering personnel developed a modification to increase the dp across the check valves on both LPCI loops. The modification was designed to decrease pressure upstream of both the "A" and "B" LPCI check valves. Specifically, the licensee cross-tied the piping upstream of the LPCI check valves to the shutdown cooling (SDC)

suction line from the "B" recirculation loop. This portion of the SDC line, between the inboard and outboard containment isolation valves, was maintained at a lower pressure than the LPCI lin Post-Modification Problems When auxiliary operators completed valving in the modification piping, pressure increased in the SDC suction header upstream of the closed outboard containment isolation valve. While the check valve banging quieted, the modification piping became hotter to the touch. Five minutes later, the SDC suction header high pressure alarm annunciated in the control room. The auxiliary operators were directed to vent the SDC header piping. Prior to the auxiliary operators venting the header, the SDC header vent valve lifted. Pressure dropped from 180 psig to 158 psig. Auxiliary operators vented the SDC header, and the high pressure alarm cleared. Auxiliary operators continued to vent the SDC header over the next few days to maintain normal header pressur The licensee formed a team of project and system engineers to determine the root cause of the SDC header high pressure problem. The licensee confirmed through testing that both the LPCI check valve, V20-0082, and the SDC outboard containment isolation valve, MO-1909, were leaking by which created a flow path from the recirculation loop to the SDC header piping. Members of the team concluded that a pressure spike occurred when operators valved in the modification, which exacerbated a known seat leakage problem on MO-190 The modification remained tagged out. The pressure downstream of the check valve will have to be periodically relieved to prevent future check valve chattering. Team members were working on ways to stop leakage past MO-1909 so that the modification could be valved back i c, Conclusions The licensee did not adequately consider long term problems with leakage past the LPCI check valve and shutdown cooling system isolation valve during development of the modification to prevent LPCI check valve chatterin E1.3 4160 Volt Breaker Plunaer/ Auxiliary Contact Gap Issue InsDection Scoce (37551 and 62707)

The inspectors observed maintenance activities on the "B" core spray pump 4160 volt breaker 1 A404. The licensee found that the gap measurement between the top of the plunger nut and auxiliary switch operator exceeded procedural requirements. The inspectors followed up on the corrective actions and held discussions with EM

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technicians, system engineers, and the electrical maintenance supervisor. The l Inspectors also reviewed the affected operating instruction, maintenance procedure, and

past correspondence between the vendor and license Observations and Findinos l

On November 3,1998, when storing the racking motor in the "B" core spray pump breaker cubicle, an auxiliary operator noticed a potential problem with the breaker. The gap between the top of the plunger nut and auxiliary contact operator on the breaker

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was wider than the procedural requirement of 1/16 inch. The operations shift personnel declared the "B" core spray pump inoperable. Electrical maintenance technicians, with the system engineer observing, reset the gap dimension. All safety-related breakers were also inspected for proper gap dimension. Two other breakers were identified with l

the same problem ("B" control rod drive pump breaker 1 A410 and standby transformer feed to essential bus breaker 1 A401).

l In 1994, the vendor issued Service Advice Letter (SAL) 073-350.1 after this problem had been identified at Duane Arnold. This SAL specifically addressed this problem. In subsequent correspondence between General Electric and the licensee regarding this issue, it was concluded a 1/8 inch gap would ensure proper auxiliary contact operatio However, the use of a 1/16 inch tolerance would also allow breaker interchangeability without the need to readjust the gap for each different breaker. The correspondence supported the conclusion that a 1/8 inch tolerance was required for operability and a 1/16 inch tolerance allowed breakers to be interchanged. The licensee did not find any of the breakers checked following identification of the problem to have exceeded the 1/8 inch requiremen The inspectors reviewed breaker maintenance procedure CKTBKR-G080-02 and operating procedures 01304.1 and 304.2 to determine if sufficient guidance was provided on how to measure and evaluate the gap. All the procedures provided sufficient guidance on the gap tolerance and how to measure the gap. The operating procedures also described the use of the go/no-go gauge to determine acceptable gap tolerance. This level of clarity was not provided in the maintenance procedur The system engineers' planned corrective actions were to revise the maintenance procedure to match the clarity of the operations procedure. Also, once the procedure revision was completed, briefs would be conducted for operatons, engineering, and

, electrical maintenance personne Conclusions The licensee identified three instances in which the plunger nut and auxiliary contact operator gap on 4160 volt breakers was greater than prescribed in the applicable procedure, but the breakers remained operable. The system engineer's root cause

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evaluation and corrective actions,' including clarifying the maintenance procedure and briefing personnel, were thorough.

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IV. Plant SuDDOrt R1 Radiological Protection and Chemistry Controls

R Daily Radiolooical Work Practices Inspection Scope (71750)

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The inspectors observed radiological worker practices during various maintenance activities detailed in this inspection report, and also monitored radiological practices during daily plant tour Observations and Findinas Without exception, the inspectors obsented that radiation protection technicians were active at job sites and were taking appropriate actions and surveys in accordance with good ALARA practices. No deficiencies were identified, Conclusions The inspectors concluded that radiological practices observed during maintenance activities and daily walkdowns were adequat V. Manaaement Meetinas l

X1 Exit Meeting Summary '

The inspectors presented the inspection results to members of licensee management at the ,

conclusion of the inspection on November 24,1998. The licensee acknowledged the findings l presented. The inspectors asked the licensee whether any materials examined during the i inspection should be considered proprietary. No proprietary information was identifie l l

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PARTIAL LIST OF PERSONS CONTACTED Licensee -

J. Franz, Vice President Nuclear -

G. Van Middlesworth, Plant Manager

R. Anderson, Manager, Outage and Support

'J. Bjorseth, Maintenance Superintendent D. Curtland, Operations Manager R. Hite, Manager, Radiation Protection M. McDermott, Manager, Engineering K. Peveler, Manager, Regulatory Performance i

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71714: Cold Weather Preparations IP 71750: Plant Support .

ITEMS OPENED, CLOSED, AND DISCUSSED Ooened None-Closed

.None Discussed None

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LIST OF ACRONYMS USED

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ALARA As low as reasonably achievable AR' ' Action Reques .

I CFR Code of Federal Regulations j CMAR Corrective Maintenance Action Request 4 DAEC _ Duane Arnold Energy Center dp Differential Pressure DR Division of Reactor Projects EM Electrical Maintenance

' IP ' Inspection Procedure i IPOl Integrated Plant Operating instructions I LPCI Low Pressure Coolant injection NRC- Nuclear Regulatory Commission PMAR Preventive Maintenance Action Request j

- PSID Pounds Per Square Inch Differential  :

PSIG Pounds Per Square Inch Gauge RHR ' Residual Heat Removal 4

.RHRSW Residual Heat Removal Service Water l SAL Service Advice Letter 1-SBDG Standby Diesel Generator

'SDC Shutdown Cooling l

'STP- Surveillance Test Procedure l

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